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1. Has there been any interest in exploring for shale gas in Massachusetts?

To our knowledge, no companies have expressed any interest in exploring for or developing shale gas in Massachusetts. In addition, to our knowledge no well driller has requested certification (310 CMR 46.00) from the Massachusetts Department of Environmental Protection (MADEP) to drill any well within Massachusetts other than water, monitoring, and geothermal wells. All well drillers are required to be certified by regulation with MADEP before they are allowed to drill any wells in Massachusetts.

2. Is hydraulic fracturing for shale gas coming to Massachusetts?

Probably not. Based on a survey of all available scientific data, the geologic conditions in the Connecticut Valley in western Massachusetts are not optimum for shale gas development. Black shale units in the Hartford Basin are generally too thin, laterally discontinuous, and are cut by too many pre-existing natural fractures and extinct faults. This makes extraction of hydrocarbons economically not feasible with today’s technology at current market prices (see below). However, more data need to be collected to completely rule out that possibility.

In addition, oil and gas wells used for conventional or enhanced hydrocarbon recovery are defined as Class 2 wells under the Massachusetts Underground Injection Control Regulations (310 CMR 27.00). Class 2 wells are currently prohibited in the Commonwealth.

3. Weren’t shale gas deposits recently found in Massachusetts by the U.S. Geological Survey (USGS)?

No. This is a common misconception of USGS Fact Sheet 2012-3075. There is sufficient information in previously published geologic literature to demonstrate that hydrocarbons were generated in the Hartford basin roughly 200 million years ago (Pratt et al., 1988). However, as stated above, due to geologic limitations there is no prospect of extraction of hydrocarbon from the Hartford basin in the foreseeable future.

The USGS Fact Sheet refers to the Hartford basin as a “composite total petroleum system” (TPS) with a potential to produce gas from the black shale deposits, which are referred to by the USGS in their report as “continuous gas accumulations”. TPS is just a term that means the essential elements (ie., source rock for hydrocarbon production, reservoir rocks to store hydrocarbons, and seal rock to trap the migrating hydrocarbon) are potentially present and processes (ie., to generate hydrocarbons through burial, to migrate hydrocarbon into reservoir rocks and to accumulate hydrocarbon in traps or as residual hydrocarbon in the black shales) may have occurred. It does NOT mean that oil and gas has been discovered and is ready for production. The USGS did NOT quantitatively assess the Hartford basin because of a lack of data. The USGS report assessed potential shale gas volumes for 5 of the 14 Mesozoic extensional basins (see below) in the eastern United States. The Hartford Basin, which underlies the Connecticut Valley, was NOT one of the basins assessed in this report.

The Hartford basin has no physical connection or geologic relationship with the Marcellus or Utica shales found in New York or Pennsylvania.

Shale gas is natural gas formed and trapped within shale formations. The gas is trapped by adsorption onto insoluble organic matter in the shale and within tiny pore spaces or micro-fractures within the shale. The gas is a mixture consisting primarily of methane and minor amounts of ethane, propane, butane, carbon dioxide, nitrogen and hydrogen sulfide, among others. Shale gas was first extracted as a resource in Fredonia, NY in 1821.

5. Shale gas is sometimes referred to as unconventional gas or as occurring in continuous gas accumulations. How is shale gas different from conventional oil and gas?

Organic-rich shales are the primary source rocks for oil and gas. When buried to great depths, the organic material is converted by heat and pressure to hydrocarbons. Over geologic time some of the oil and gas can migrate out of the source rocks through pores and fractures into overlying and more porous sandstones and carbonate rocks, referred to as reservoir rocks. The oil and gas will migrate through the reservoir rocks until it hits a cap rock of impervious material that impedes upward and lateral migration to the land surface. The trapped oil and gas is then extracted by production wells. These accumulations generally consist of formation waters (mineral-rich waters known as brines) at the base, which are overlain successively by oil and natural gas. This is referred to as conventional oil and gas.

In most cases, however, some of the gaseous hydrocarbons are too tightly bound to organic material in the shale and cannot escape. In other cases, the shale and surrounding rocks are too impermeable to allow gas to migrate out of the source rock into adjacent rock formations. In yet others, hydrocarbon gases are produced by microorganisms living in the rocks. These all are known as unconventional or continuous gas accumulations. In many unconventional gas resource deposits, hydraulic fracturing is used as a cost-effective means to make more of the potential reservoirs accessible for natural gas production.

6. What is shale?

Shale is a sedimentary rock that is made predominantly of very fine-grained clay particles deposited in very thin layers. These rocks were originally deposited as mud in low energy depositional environments, such as tidal flats, swamps, lakes, and deep-ocean basins where the clay particles dropped out of suspension from the water column. Deep burial of this mud results in a layered rock called shale, which actually describes the very fine grained and laminated nature of the sediment, not its rock composition. The composition of shales varies widely, and only some are rich in organic materials that can generate natural gas.

7. How does shale gas form?

During deposition of the muds that form shales, organic matter is also deposited, particularly in swamps and lakes. The amount of organic matter in a rock is measured by a parameter called Total Organic Carbon (TOC). Shale gas is produced from organic-rich shales, also known as black shale. These are shales with greater than 1% TOC. Plant and algal remains and the animal forms that consume them are buried with the sediment. As the sediment load increases due to continued burial, heat and pressure converts some of this organic material into hydrocarbons (compounds made of hydrogen and carbon). Conversion of this initial organic material (called kerogen) into petroleum causes an increase in rock pressure, which expels the oil and gas from the shales into adjacent strata. Continued pressure from burial may allow much of the natural gas to migrate from the organic shales into overlying reservoir rocks. The natural gas that remains tightly bound in the shale is the unconventional shale gas.

8. Do we have organic rich black shales in Massachusetts?

Yes. There are numerous (perhaps 15 to 20) examples of Lower Jurassic black shales in the Connecticut Valley but these occur as very thin beds (Fig. 1; Pratt et al., 1988). Bed thicknesses average from 3 to 6 feet to just a few inches (Kruge et al., 1989). Some beds may be up to 25 feet thick in Connecticut but are laterally discontinuous and do not cover large areas. These beds are typically separated by an average of 30 or more feet of water laid (fluvial) red sandstones and siltstones (Hubert et al., 1992).

Total cumulative thickness of the black shales in the Connecticut valley of Massachusetts is estimated to be between 100 and 130 feet (Pratt and Burruss, 1988) and no more than 160 feet (Hubert, person. communication, 2012). The shale beds occur within a 5000-6000 foot thick (~1.1 miles) stack of fluvial and lacustrine sandstones, mudstones, conglomerates, and flood basalt (Fig. 2).

The average organic content of the black shales is about 2% by weight (Pratt et al., 1988) but can be as high as 3 to 7.6%. Samples of rock from the Connecticut valley show that oil and gas has migrated out of some of these black shales in the geologic past as evidenced by bitumen in fluid inclusions, mineralized veins, coated fractures and stained sand grains in adjacent rocks (Pratt and Burruss, 1988).

9. So is there any conventional oil and gas found in the Connecticut valley in economic quantities?

Most of the published evidence indicates that with today’s prices and technology there is likely no economically viable conventional or unconventional oil and gas in the Connecticut valley (Pratt and Burruss, 1988; Hubert et al., 2001).

The rocks are either thermally overmature, meaning they have been heated beyond the oil and gas thermal generation window (Fig. 3), or there is no trapping geometry of strata which could have contained migrating hydrocarbons after they were produced. Accordingly, most of the economically viable oil and gas probably volatilized and seeped to the surface long ago, roughly 170 million years ago (Hubert et al., 1992). All that is left behind in present day rocks is the residual trail. The area where the thermal regime may be most favorable for oil in Massachusetts is in the northeast part of the Hartford basin south and east of the Holyoke Range (Fig. 3).

10. Have any companies expressed interest in evaluating conventional oil or gas potential in the Connecticut valley in the past?

Yes. Texaco did some exploratory geophysical work in the 1970s. They did not return to the Connecticut Valley and no exploration drilling was carried out. In the late 1980s Texaco funded some work to examine the burial, diagenesis and hydrothermal history of the Connecticut Valley (Taylor, 1991; Hubert et al., 1992, 2001). No further exploration was conducted.

11. Do any of the black shales in the Hartford basin contain shale gas?

Probably, however, several factors suggest that extraction is most likely not practical or economically feasible with current technology at present day gas prices. The black shale units are thin, of variably thickness and laterally discontinuous. In most cases, the individual beds that would be targeted are only 3 to 6 feet thick. Although they may be capable of storing substantial amounts of hydrocarbon, the petroleum can diffuse out into adjacent rocks relatively quickly due to the thin nature of the beds; it is a leaky source rock at best. In addition, the Connecticut valley shales have locally been heated by lava flows and hydrothermal fluids (Hubert et al., 2001; Hubert et al., 1992; Pratt et al., 1988) leading to locally overly mature deposits and limiting the areal extent of any potential extractable resource (Pratt et al., 1988).

Thick (100 to 300+ feet) and laterally extensive (several 10’s to 100’s of miles) sequences of black shale like the Marcellus, Utica and Barnett Shales DO NOT EXIST in the Connecticut valley.

In the USGS assessment, associated tight sandstones were considered to be part of the continuous gas accumulations evaluated. Under certain conditions, such as those that occur within the Silurian sandstones of Ohio, tight sandstones associated with shale source rocks may contain large unconventional (continuous) accumulations of natural gas. The geological environments of the accumulations in Ohio, which extend over many square miles, are considerably different than those that occur within the Hartford basin.

However, more data are needed to fully understand the geology and hydrocarbon potential of the basin. These additional data include exploratory boreholes and rock cores to determine the actual thickness and continuity of the target shale beds, seismic reflection surveys, geochemical analyses, tests to determine the amount of gas in storage within the shale and the degree of fracturing of the host rocks. Recent geologic mapping in Connecticut shows that the rock units in some parts of the Connecticut Valley are highly fractured and faulted with minor offsets (M. Thomas, email communication, 12/3/12). Accordingly, drilling targets would be difficult to site because of the structural discontinuities in the rock (such as naturally occurring fractures and extinct faults) potentially limiting the sustainability of any production.

12. What is the Hartford Basin?

The Connecticut valley originated as a rift basin where the Earth’s crust began to pull apart during the opening of the modern Atlantic Ocean in the Triassic and Jurassic periods (ie., geologic periods of time) about 220 million years ago. The rifting was part of the breakup of the supercontinent Pangea. Rifting creates a topographic lowland, or basin, into which sediments from the surrounding highlands are deposited (Fig. 4). These sediments can accumulate to great thicknesses depending on how fast the basin subsides. It is estimated that the depth of the Connecticut Valley rift basin is 13,000 to 16,000 feet. Locally drainage was impeded to allow a variety of shallow lakes to form as the basin subsided.

13. Where is the Hartford Basin?

The rift basin extends from the Vermont border almost to the Connecticut shoreline generally parallel with the Connecticut River. The basin can be divided into two parts using an east west imaginary line through the town of Amherst as the dividing line. North of Amherst (north of the Holyoke Range) the basin is referred to as the Deerfield basin, south of Amherst (including the Holyoke Range) it is called the Hartford basin. In Massachusetts, the Hartford basin is approximately 15 miles wide and 19 miles long whereas the Deerfield basin averages 3 miles wide by 15 miles long (Figs. 5 and Fig. 6).

14. Where are the organic rich black shales within the Hartford and Deerfield Basins?

The table below lists the rock formations that are found in the Hartford and Deerfield basins and their respective thicknesses. An asterisk next to the formation name means the rock formation contains black shale beds within the unit. These thicknesses are for the entire formation and are NOT the thicknesses of the black shales within that formation.

Hartford Basin (oldest unit on bottom to youngest on top)

Approx. Thickness (ft)

Deerfield Basin (oldest unit on bottom to youngest on top)

Approx. Thickness (ft)

Portland Formation*

8000

Mount Toby Conglomerate/

1000

Hampden Basalt

300

Turners Falls Formation*

6560

East Berlin Formation*

550

Deerfield Basalt

330

Holyoke Basalt

300

Fall River Beds*

30

Shuttle Meadow Formation*

450

Sugarloaf Arkose

5600

Talcott Basalt

300

New Haven Arkose

6000

The black shales formed in temporary non-saline, somewhat anoxic lakes with very poor circulation allowing the accumulation of organic matter with the sediment (Fig. 7). The lakes formed during rapid extension and subsidence of the basin in the lower Jurassic period. The organic material was derived from a mixture of algae, woody plant debris and some soil organic matter (Spiker et al., 1988).

15. Is there any evidence that shale gas can be produced from any of the black shales in the Hartford and Deerfield Basins?

No oil or gas wells have been drilled to test any of the strata within the Hartford and Deerfield Basins. Therefore, there is no direct evidence that oil or gas can or cannot be produced here. However, outcrop samples have been examined, which may illuminate the petroleum potential of the black shales within the basins. Some samples from the Portland Formation in the Hartford basin indicate that the rocks locally are thermally immature meaning subsurface temperatures did not rise high enough and the thermal maturation needed for effective petroleum generation was not achieved (Pratt et al., 1988). The black shales in the Shuttle Meadow and East Berlin Formations did fall in places within peak conditions for petroleum generation (Pratt et al., 1988; Hubert et al., 1992) and are located in the southeast portion of the Hartford basin underlying Massachusetts (Holyoke, Springfield and Longmeadow) south and east of the Holyoke Range (Fig. 3) . However these units are thin, laterally discontinuous and fractured. Samples from the black shales in the Deerfield Basin north of the Holyoke Range have experienced several episodes of hydrothermal alteration (Hubert et al., 1992; 2001) and thus are thermally overmature and probably not a commercial source for shale gas.

16. What is hydraulic fracturing?

Hydraulic fracturing, also known as fracking, involves a borehole or well that has been drilled into the subsurface to reach a targeted formation, and then the pumping of a fracturing fluid into that formation at a calculated, predetermined rate and pressure in order to crack the rock and create artificial fractures in the target formation. Hydraulic fracturing well completions typically use water or water-based fluids as the fracture fluids, mixed with a small amount of various additives (see below). Sand is also added to the mixture as a proppant (meaning to prop open), which is needed to prop open the fractures once the fracturing process has stopped.

17. What is different about shales and why are they hydraulically fractured?

All low porosity and permeability potential reservoir rocks require hydraulic fracture stimulations. The permeability of a typical shale (ability of fluids to move freely through the material) is very low (often termed ultra low), which means that hydrocarbons are effectively trapped within the shale and unable to flow under normal circumstances, and usually only migrate out of the shale as it is compacted over geologic time. In order to increase the permeability of the shale so that the tightly bound hydrocarbons can be released and extracted by a production well, the formation is artificially stimulated by hydraulic fracturing. Hydraulic fracturing expands the width of narrow, naturally-existing fractures in the rock and creates new ones. Overall this increases the permeability of the shale in the vicinity of a gas well. Only then can the residual gas in the shale be accessible for extraction.

18. How is shale gas accessed?

Shale gas is accessed by drilling a production well into the black shale formation from the ground surface. The drilling pad consists of a drill rig with a derrick, chemical storage tanks, sand and hydraulic fracturing fluid storage tanks, pumps, and monitoring van, settling ponds and wastewater retention ponds, among other things. Each drilling pad may have from 2 to 15 wellheads each targeting the same shale unit. Pads might be 5 to 7 acres in size during drilling but are reduced in size once drilling is completed and production begins (King, 2012). http://www.kgs.ku.edu/PRS/Fracturing/Frac_Paper_SPE_152596.pdf

The process begins by drilling a vertical hole and running jointed casing into the hole. The depth of the initial vertical hole depends on how deep it is to the deepest fresh water aquifer. Cement is then pumped down the casing which then flows up the annulus (space between the casing and the surrounding rock) sealing and separating the well bore from the surrounding environment. This casing is set several hundred feet below the deepest freshwater aquifer and is pressure tested and logged to determine the integrity of the cement bond. The integrity of the cement job is the key to preventing methane and water from lower shale formations under high pressure from moving up the annulus to the surface where it can contaminate shallow aquifers or reach the surface (King, 2012). For more information about cementing wells see Nelson (1990).

After the first casing is set and tested, a smaller drill bit is inserted into the well bore and the hole advanced to the target shale. There may be multiple strings of casing nested inside one another, each casing string being successively smaller in diameter. Once the vertical hole reaches the target depth the well may be turned in a direction parallel with the producing shale bed. This may be horizontal or slightly inclined depending on the attitude of the bed. The length of the horizontal section of the well may vary from 1000 to 6000 feet in length, sometimes longer. The time needed to complete the entire drilling operation is usually 1 month to several months depending on the number of wells (King, 2012).

Once the horizontal portion of the well is drilled, cased and sealed specialized equipment is used to isolate a portion of the borehole and perforate the casing creating a connection between the shale formation and the pipe. The hydraulic fracturing fluid containing water and sand is then pumped into the isolated section of the perforated casing and shot into the shale formation creating hundreds of minute cracks that can sometimes propagate a couple of hundred of feet away from the borehole. The sand then fills the cracks; holding them open and allowing the gas to flow freely into the pipe and to the surface. Hydraulic fracturing is conducted in stages and each stage may last from 20 minutes to up to 4 hours (King, 2012).

The hydraulic fracturing fluid is 90% water, 9.5% sand (silica sand) and 0.5% additives. The additives include: 1) acids to help dissolve minerals and initiate pre-fracture of the rock; 2) sodium chloride (table salt) to allow delayed breakdown of gel polymer chains; 3) polyacrylamide (friction reducer) to minimize friction between the fluid and the pipe; 4) ethylene glycol (scale inhibitors) to prevent mineral deposits in the pipe; 5) borate salts for maintaining fluid viscosity as the temperature increases with depth; 6) sodium and potassium carbonate for pH control; 7) Glutaraldehyde (biocide disinfectant) to control bacteria in the water; 8) Guar Gum (gel polymers) to thicken the fluid so the sand can stay suspended; 9) citric acid (iron control) to prevent the precipitation of metal oxides; and, 10) isopropanol (surfactant) to increase the viscosity of the fracking fluid. Variations of these 10 components include 29 different chemicals in 652 different products and can include such substances as xylene, benzene, and toluene, among others. The proportion of these additives and the specific products used by drillers varies depending on the depth, type of formation and other geologic factors. For more details on the quantities and types of additives see (King, 2012, p.8; Whittemore, 2011)

The report lists 29 chemicals in 652 different products that are: 1) known or possible human carcinogens; 2) regulated under the Safe Drinking Water Act for their risks to human health; or, 3) listed as hazardous air pollutants under the Clean Air Act.

21. Is reporting required for chemicals used as additives to the hydraulic fracturing fluid?

No. However, the range of chemicals used is well known. What is uncertain are the specifics about which products are used and in what proportion at a given drill pad. Several states are now requiring companies to disclose what chemicals they are using. States that have developed or are developing disclosure laws include Arkansas, Colorado, Idaho, Montana, New Mexico, North Dakota, Pennsylvania, Texas, West Virginia, and Wyoming (http://fracfocus.org/chemical-use/chemicals-public-disclosure). Further, the Ground Water Protection Council and Interstate Oil and Gas Compact Commission have developed a registry and database where industry can voluntarily submit to the database information about their shale gas wells, including the chemicals used for fracking. The database has 33,277 wells registered as of December 6, 2012. The site is available to the public at: http://fracfocus.org/

22. How much water is used during a typical hydraulic fracturing operation?

Water is needed during the drilling operation to cool the bit and mix with drilling mud, which holds the hole open while drilling, and it is also used as the primary component of the hydraulic fracturing fluid. The actual quantity of water used depends on the well depth, formation and pressure needed in the fracking process. The amount of water needed to drill a well can be as little as 420,000 gallons up to 1 million gallons. The hydraulic fracturing process may use as little as 42,000 gallons to as much as 2.49 million gallons of water, sometimes more. Commonly 2-8 million gallons of water are used for each Marcellus horizontal well. At one time, this was a one-time use of the water. Now, however, companies are recycling and reusing their fracture fluid through several wells. King (2012, p.40) provides some typical water usage figures for drilling and hydraulic fracturing operations in some of the major shale gas plays in the U.S. http://www.kgs.ku.edu/PRS/Fracturing/Frac_Paper_SPE_152596.pdf

Assuming a total of 3.49 million gallons for drilling and hydraulic fracturing a single well, that is equivalent to:

23. Is there a fluid byproduct produced from the drilling and fracking operation?

Yes. After the fracking process is completed some of the hydraulic fracturing fluid is absorbed or lost to the formation and some of it returns up the well bore to the surface (called flowback) because the subsurface is overpressured during hydraulic fracturing. This overpressure forces some of the fluids up the borehole. Flowback of hydraulic fracturing fluids during the first two to three weeks after hydraulic fracturing ceases may produce 125 to 250 gallons per minute, for a few hours, dropping to 29 gallons per minute within 24 hours and then quickly decreasing during the next 2 to 3 weeks (King, 2012). For more information on hydraulic fracturing fluid see:

“Horizontal wells and hydraulic fracturing are not new tools for the oil and gas industry. The first fracturing experiment was in 1947 and the process was accepted commercially by 1950. The first horizontal well was in the 1930s and horizontal wells were common by the late 1970s” (King, 2012, p.2). It is estimated by the Society of Petroleum Engineers that over 1 million hydraulically fractured wells have been completed in the U.S. and over 2.5 million world-wide (King, 2012, p.2). Over 550 papers have been published on the subject of shale fracturing and another 3000 on horizontal well technology and cover nearly 30 plus years of development in shale technology (King, 2012, p.2).

25. Are there environmental risks associated with hydraulic fracturing?

Yes. Any major drilling or industrial operation has risks. Potential contamination of fresh groundwater, water consumption, earthquakes triggered by injecting fluids, venting or flaring of methane and disposal of fluids are common environmental concerns associated with hydraulic fracturing, drilling and production operations. For more information on the risks and safeguards see:

Pratt, L.M. and Burruss, R.C. 1988. Evidence for petroleum generation and migration in the Hartford and Newark basins, in Froelich, A.J. and Robinson, G.R., eds., Studies of the Early Mesozoic Basins of the Eastern United States. U.S. Geological Survey Bulletin 1776, pp.74-79.

Pratt, L.M., Shaw, C.A., and Burruss, R.C. 1988. Thermal histories of the Hartford and Newark basins inferred from maturation indices of organic matter, in Froelich, A.J. and Robinson, G.R., eds., Studies of the Early Mesozoic Basins of the Eastern United States. U.S. Geological Survey Bulletin 1776, pp.58-62.

Spiker, E.C., Kotra, R.K., Hatcher, P.G., Gottfried, R.M., Horan, M.F., and Olsen, P.E. 1988. Source of kerogen in black shales from the Hartford and Newark basins, eastern United States, in Froelich, A.J. and Robinson, G.R., eds., Studies of the Early Mesozoic Basins of the Eastern United States. U.S. Geological Survey Bulletin 1776, pp.63-68.

Taylor, J.M. 1991. Diagenesis of sandstones in the early Mesozoic Deerfield basin, Massachusetts. M.S. Thesis: Department of Geosciences, University of Massachusetts, Amherst, 225p.